<PAGE>
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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                              -------------------

                                   FORM 10-Q

<TABLE>
<S>              <C>
/X/              QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                 SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD
                 ENDED MARCH 31, 2001
</TABLE>

                                       OR

<TABLE>
<S>              <C>
/ /              TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                 SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD
                 FROM TO
</TABLE>

                         COMMISSION FILE NUMBER: 0-6910

                               -----------------

                               TEL OFFSHORE TRUST
             (Exact Name of Registrant as Specified in its Charter)

<TABLE>
<S>                                            <C>
                 TEXAS                                      76-6004064
       (State of Incorporation,                          I.R.S. Employer
           or Organization)                            Identification No.)

       THE CHASE MANHATTAN BANK
       CORPORATE TRUST DIVISION
           700 LAVACA STREET
             AUSTIN, TEXAS
         (Address of Principal
          Executive Offices)
                                                              78701
                                                            (Zip Code)
</TABLE>

       Registrant's Telephone Number, Including Area Code: (512) 479-2562

    Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days.  Yes X  No _

    Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.

    As of May 8, 2001 -- 4,751,510 Units of Beneficial Interest in TEL Offshore
Trust.

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<PAGE>
                   NOTE REGARDING FORWARD-LOOKING STATEMENTS

    This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q are forward-looking
statements. Although the Working Interest Owners (as defined herein) have
advised the Trust that they believe that the expectations reflected in the
forward-looking statements contained herein are reasonable, no assurance can be
given that such expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from expectations
("Cautionary Statements") are disclosed in this Form 10-Q, including without
limitation in conjunction with the forward-looking statements included in this
Form 10-Q. All subsequent written and oral forward-looking statements
attributable to the Trust or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.

                                       i
<PAGE>
                         PART I--FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<TABLE>
<CAPTION>
                                                               MARCH 31,    DECEMBER 31,
                                                                 2001           2000
                                                              -----------   -------------
                                                              (UNAUDITED)
<S>                                                           <C>           <C>
ASSETS
Cash and cash equivalents...................................  $2,575,975     $3,922,089
Net overriding royalty interest in oil and gas properties,
  net of accumulated amortization of $28,013,439 and
  $27,998,574, respectively.................................     254,216        269,081
                                                              ----------     ----------
Total assets................................................  $2,830,191     $4,191,170
                                                              ==========     ==========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders........................  $1,597,004     $2,804,605
Reserve for future Trust expenses...........................     978,971      1,117,484
Commitments and contingencies (Note 7)
Trust corpus (4,751,510 Units of beneficial interest
  authorized and outstanding)...............................     254,216        269,081
                                                              ----------     ----------
Total liabilities and Trust corpus..........................  $2,830,191     $4,191,170
                                                              ==========     ==========
</TABLE>

                       STATEMENTS OF DISTRIBUTABLE INCOME
                                  (UNAUDITED)

<TABLE>
<CAPTION>
                                                                THREE MONTHS ENDED
                                                                     MARCH 31,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
<S>                                                           <C>          <C>
Royalty income..............................................  $1,518,643   $1,251,181
Interest income.............................................      36,909       18,017
                                                              ----------   ----------
                                                               1,555,552    1,269,198
Decrease in reserve for future Trust expenses...............     138,513      266,759
General and administrative expenses.........................     (97,061)     (77,608)
                                                              ----------   ----------
Distributable income........................................  $1,597,004   $1,458,349
                                                              ==========   ==========
Distributions per Unit (4,751,510 Units)....................  $  .336105   $  .306923
                                                              ==========   ==========
</TABLE>

   The accompanying notes are an integral part of these financial statements.

                                       1
<PAGE>
                     STATEMENTS OF CHANGES IN TRUST CORPUS
                                  (UNAUDITED)

<TABLE>
<CAPTION>
                                                                 THREE MONTHS ENDED
                                                                      MARCH 31,
                                                              -------------------------
                                                                 2001          2000
                                                              -----------   -----------
<S>                                                           <C>           <C>
Trust corpus, beginning of period...........................  $   269,081   $   367,768
Distributable income........................................    1,597,004     1,458,349
Distribution payable to Unit holders........................   (1,597,004)   (1,458,349)
Amortization of net overriding royalty interest.............      (14,865)      (19,551)
                                                              -----------   -----------
Trust corpus, end of period.................................  $   254,216   $   348,217
                                                              ===========   ===========
</TABLE>

   The accompanying notes are an integral part of these financial statements.

                                       2
<PAGE>
                               TEL OFFSHORE TRUST

                         NOTES TO FINANCIAL STATEMENTS

                                  (UNAUDITED)

NOTE 1 -- TRUST ORGANIZATION

    Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore
Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution
("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In
accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was
formed in which the Trust owns a 99.99% interest and Tenneco Oil Company
("Tenneco") initially owned a .01% interest. In general, the Plan was effected
by transferring an overriding royalty interest ("Royalty") equivalent to a 25%
net profits interest in the oil and gas properties (the "Royalty Properties") of
Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the
Partnership and issuing certificates evidencing units of beneficial interest in
the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common
stock.

    On October 31, 1986, Exploration I was dissolved and the oil and gas
properties of Exploration I were distributed to Tenneco subject to the Royalty.
Tenneco, who was then serving as the Managing General Partner of the
Partnership, assumed the obligations of Exploration I, including its obligations
under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash
distributions to holders of units of beneficial interest.

    On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the
Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.

    On October 30, 1992, PennzEnergy Company ("PennzEnergy") acquired certain
oil and gas producing properties from Chevron, including four of the Royalty
Properties. The four Royalty Properties acquired by PennzEnergy were East
Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a
result of such acquisition, PennzEnergy replaced Chevron as the Working Interest
Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's
obligations under the Conveyance with respect to such properties.

    On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired two of the Royalty Properties from Chevron. The Royalty Properties
acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result
of such acquisitions, Texaco replaced Chevron as the Working Interest Owner of
such properties on December 1, 1994. Texaco also assumed Chevron's obligations
under the Conveyance with respect to such properties.

    On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced
PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, on October 1, 1995 and also assumed
PennzEnergy's obligations under the Conveyance with respect to such properties.

                                       3
<PAGE>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

    Effective January 1, 1998, Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property. In
October 1998, Amerada Hess Corporation ("Amerada") acquired the East Cameron 354
property from Energy effective January 1, 1998. As a result of such acquisition,
Amerada replaced Energy as the Working Interest Owner of the East Cameron 354
property effective January 1, 1998, and also assumed Energy's obligations under
the Conveyance with respect to such property.

    Effective January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada)
merged into Devon Energy Production Company L.P., ("Devon"). As a result of such
merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene
Island 348 and Eugene Island 208 properties effective January 1, 2000, and also
assumed PennzEnergy's obligations under the Conveyance with respect to such
properties.

    All of the Royalty Properties continue to be subject to the Royalty, and it
is anticipated that the Trust and the Partnership, in general, will continue to
operate as if the above-described sales of the Royalty Properties had not
occurred.

    Unless the context in which such terms are used indicates otherwise, in
these Notes to Financial Statements the terms "Working Interest Owner" and
"Working Interest Owners" generally refer to the owner or owners of the Royalty
Properties (Exploration I through October 31, 1986; Tenneco for periods from
October 31, 1986 until November 18, 1988; Chevron with respect to all Royalty
Properties for periods from November 18, 1988 until October 30, 1992, and with
respect to all Royalty Properties except East Cameron 354, Eugene Island 348,
Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until
December 1, 1994, and with respect to the same properties except West Cameron
643 and East Cameron 371/381 thereafter; PennzEnergy with respect to East
Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for
periods from October 30, 1992 until October 1, 1995, and with respect to Eugene
Island 348 and Eugene Island 208 until January 1, 2000; Texaco with respect to
West Cameron 643 and East Cameron 371/381 for periods beginning on or after
December 1, 1994; SONAT with respect to East Cameron 354 for periods beginning
on or after October 1, 1995; and Amoco with respect to Eugene Island 367 for
periods beginning on or after October 1, 1995; and Amerada with respect to East
Cameron 354 for periods beginning on or after January 1, 1998; and Devon with
respect to Eugene Island 348 and Eugene Island 208 for periods beginning on or
after January 1, 2000).

NOTE 2 -- BASIS OF ACCOUNTING

    The accompanying unaudited financial information has been prepared by The
Chase Manhattan Bank (formerly known as Chase Bank of Texas, National
Association) ("Corporate Trustee") in accordance with the instructions to
Form 10-Q and does not include all of the information required by accounting
principles generally accepted in the United States of America for complete
financial statements, although the Corporate Trustee and the individual trustees
(collectively, the "Trustees") believe that the disclosures are adequate to make
the information presented not misleading. The information furnished reflects all
adjustments which are, in the opinion of the Trustees, necessary for a fair
presentation of the results for the

                                       4
<PAGE>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

interim periods presented. The financial information should be read in
conjunction with the financial statements and notes thereto included in the
Trust's Annual Report on Form 10-K for the year ended December 31, 2000.

    The financial statements of the Trust are prepared on the following basis:

       (a) Royalty income is recorded when received by the Corporate Trustee on
           the last business day of each calendar quarter; and

       (b) Trust general and administrative expenses are recorded when paid,
           except for the cash reserved for future general and administrative
           expenses, as discussed in Note 6.

    This manner of reporting income and expenses is considered to be the most
meaningful because the quarterly distributions to Unit holders are based on net
cash receipts received from the Working Interest Owners. The financial
statements of the Trust differ from financial statements prepared in accordance
with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would
be recognized on an accrual basis. In addition, amortization of the overriding
royalty interest, which is calculated on a units-of-production basis, is charged
directly to Trust corpus since such amount does not affect distributable income.

    Cash and cash equivalents include all highly liquid, short-term investments
with original maturities of three months or less.

    The Trust reviews net overriding royalty interest in oil and gas properties
for possible impairment whenever events or circumstances indicate the carrying
amount of the asset may not be recoverable. If there is an indication of
impairment, the Trust prepares an estimate of future cash flows (undiscounted
and without interest charges) expected to result from the use of the asset and
its eventual disposition. If these cash flows are less than the carrying amount
of the asset, an impairment loss is recognized to write down the asset to its
estimated fair value. Preparation of estimated expected future cash flows is
inherently subjective and is based on management's best estimate of assumptions
concerning expected future conditions. There were no write downs taken in the
periods presented.

    The preparation of financial statements requires the Trustees to make use of
estimates and assumptions that affect amounts reported in the financial
statements as well as certain discounts. Actual results could differ from those
estimates.

    The amount of cash distributions by the Trust is dependent on, among other
things, the sales prices for oil and gas produced from the Royalty Properties
and the quantities of oil and gas sold. It should be noted that substantial
uncertainties exist with regard to future oil and gas prices, which are subject
to material fluctuations due to changes in production levels and pricing and
other actions taken by major petroleum producing nations, as well as the
regional supply and demand for gas, weather, industrial growth, conservation
measures, competition and other variables. The Trust does not enter into any
hedging transactions on future production. Accordingly, the Statement of
Financial Accounting Standards No. 133, "Accounting of Derivative Instruments
and Hedging Activities," as amended, that was effective January 1, 2001 has not
had an impact on the financial statements.

                                       5
<PAGE>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

NOTE 3 -- NET OVERRIDING ROYALTY INTEREST

    The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated
January 1, 1983, provides that the Working Interest Owners will calculate, for
each period of three months commencing the first day of February, May, August
and November, an amount equal to 25% of the Net Proceeds from their oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals from the Royalty
Properties less operating and capital costs incurred, management fees and
expense reimbursements owing to the Managing General Partner of the Partnership,
applicable taxes other than income taxes, and a special cost reserve. The
Special Cost Reserve Account is established for the future costs to be incurred
to plug and abandon wells, dismantle and remove platforms, pipelines and other
production facilities, and for the estimated amount of future capital
expenditures on the Royalty Properties. Net Proceeds do not include amounts
received by the Working Interest Owners as advance gas payments, "take-or-pay"
payments or similar payments unless and until such payments are extinguished or
repaid through the future delivery of gas.

NOTE 4 -- DISTRIBUTIONS TO UNIT HOLDERS

    In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. The
amounts distributed are determined on a quarterly basis and are payable to Unit
holders of record as of the last business day of each calendar quarter. However,
cash distributions are made in January, April, July and October and include
interest earned from the quarterly record date to the date of distribution.

NOTE 5 -- SPECIAL COST ESCROW ACCOUNT

    The Conveyance provides for the reserve of funds for estimated future
"Special Costs" of plugging and abandoning wells, dismantling platforms and
other costs of abandoning the Royalty Properties, as well as for the estimated
amount of future drilling projects and other capital expenditures on the Royal
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on certain factors, including estimates of aggregate future
production costs, aggregate future Special Costs, aggregate future net revenues
and actual current net proceeds. Deposits into this account reduce current
distributions and are placed in an escrow account and invested in short-term
certificates of deposit. Such account is herein referred to as the "Special Cost
Escrow Account." The Trust's share of interest generated from the Special Cost
Escrow Account serves to reduce the Trust's share of allocated production costs.
Special Cost Escrow funds will generally be utilized to pay Special Costs to the
extent there are not adequate current net proceeds to pay such costs. Special
Costs that have been paid are no longer included in the Special Cost Escrow
calculation. Deposits to the Special Cost Escrow Account will generally be made
when the balance in the Special Cost Escrow Account is less than 125% of future
Special Costs and there is a Net Revenues Shortfall (a calculation of the excess
of estimated future costs over estimated future net revenues pursuant to a
formula contained in the Conveyance). When there is not a Net

                                       6
<PAGE>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

Revenues Shortfall, amounts in the Special Cost Escrow Account will generally be
released, to the extent that Special Costs have been incurred. Amounts in the
Special Cost Escrow Account generally will also be released when the balance in
such account exceeds 125% of future Special Costs. In the first quarter of 2000,
there was a net deposit of funds into the Special Cost Escrow Account. The
Trust's share of the funds deposited was approximately $265,000. The deposit was
primarily a result of an increase in the Working Interest Owners' current
estimate of projected capital expenditures on the Royalty Properties. In the
first quarter of 2001, there was a net deposit of funds into the Special Cost
Escrow Account. The Trust's share of the funds deposited was approximately
$423,125. The deposit was primarily a result of an increase in the Working
Interest Owners' current estimate of projected capital expenditures of the
Royalty Properties. As of March 31, 2001, approximately $5,733,000 remained in
the Special Cost Escrow Account.

    Chevron, in its capacity as Managing General Partner, has advised the Trust
that additional deposits to the Special Cost Escrow Account may be required in
future periods in connection with other production costs, other abandonment
costs, other capital expenditures and changes in the estimates and factors
described above. Such deposits could result in a significant reduction in
Royalty income in the periods in which such deposits are made, including the
possibility that no Royalty income would be received in such periods.

NOTE 6 -- EXPENSE RESERVE

    The Trust made a determination in 1998 to maintain a cash reserve equal to
three times the average expenses of the Trust during each of the past three
years to provide for future administrative expenses in connection with the
winding up of the Trust. The reserve amount for 2000 was $1,117,484. The excess
amount in the reserve of $266,759 was distributed to Unit holders in the first
quarter of 2000. The reserve amount for 2001 is $978,971. The excess amount in
the reserve of $138,513 was distributed to Unit holders in the first quarter of
2001.

NOTE 7 -- COMMITMENTS AND CONTINGENCIES

    During 1994, PennzEnergy, the Working Interest Owner on the Eugene Island
348 property, settled a gas imbalance on that property for approximately
$2,696,000. The Trust's share of this settlement amount was approximately
$674,000, of which approximately $500,680 has been recovered from the Trust by
Devon (as successor of PennzEnergy) through the first quarter of 2001. The
remainder will be subject to recovery from the Trust during future periods in
accordance with the Conveyance. Devon has advised the Trust that future Royalty
income attributable to all of the Royalty Properties owned by Devon will be used
to offset the Trust's share of such settlement amounts. Based on current
production, prices and expenses for the Royalty Properties owned by Devon, it is
estimated that Royalty income attributable to such properties will be retained
by Devon for the remaining life of the Trust. The Trust does not anticipate that
retention of such Royalty income by PennzEnergy will have a material effect on
the Trust's Royalty income as a whole.

    The Working Interest Owners have advised the Trust that, although they
believe that they are in general compliance with applicable health, safety and
environmental laws and regulations that have taken effect at the federal, state
and local levels, costs may be incurred to comply with current and proposed
environmental legislation which could result in increased operating expenses on
the Royalty Properties.

                                       7
<PAGE>
ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS.

FINANCIAL REVIEW

THREE MONTHS ENDED MARCH 31, 2001 AND 2000

    Distributions to Unit holders for the three months ended March 31, 2001
amounted to $1,597,004 or $.336105 per Unit as compared to $1,458,349 or
$.306923 per Unit for the same period in 2000. The increase in distributable
income for the first quarter of 2001 was primarily due to increased oil and gas
prices, offset by production volume declines, as described below

    Gas revenues increased $1,007,914, or 25%, to $4,021,809 in the first
quarter of 2001 from $3,013,895 in the first quarter of 2000, primarily due to a
174% increase in the average price received for natural gas to $6.98 per Mcf in
the first quarter of 2001 from $2.55 per Mcf in the first quarter of 2000. The
increase in average price was partially offset by a 51% decrease in gas volumes
to 576,302 Mcf in the first quarter of 2001 from 1,181,948 Mcf in the first
quarter of 2000.

    Crude oil and condensate revenues decreased $257,694, or 5%, to $4,997,290
in the first quarter of 2001 as compared to $5,254,984 in the same period in
2000, primarily due to a 21% decrease in crude oil and condensate volume from
the 2000 first quarter to the 2001 first quarter. The decrease in crude oil and
condensate volumes was partially offset by a 20% increase in the average price
of crude oil and condensate from $25.22 per barrel in the first quarter of 2000
to $30.35 per barrel in the first quarter of 2001.

    The Trust's share of capital expenditures decreased approximately 80% or
$771,545 in the first quarter of 2001 as compared to the same period in 2000
primarily due to drilling activities on the B-18 sidetrack well and improvements
on the platform B facilities on the Eugene Island 339 property in the first
quarter of 2000.

    For the first quarter of 2001, the Trust had undistributed net income of
$164,248. Undistributed net loss represents negative Net Proceeds generated
during the respective period. Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. An undistributed net loss is carried forward and
offset, in future periods, by positive Net Proceeds earned by the related
Working Interest Owner(s). The undistributed net income for the first quarter of
2001 was primarily related to the loss carryforward referred to above on the
Eugene Island 348 property.

    In the first quarter of 2001, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $423,125, compared to a net deposit of funds from the Special Cost
Escrow Account of $264,979 net to the Trust in the first quarter of 2000. The
Special Cost Escrow is set aside for estimated abandonment costs and future
capital expenditures as provided for in the Conveyance. For additional
information relating to the Special Cost Escrow see "Special Cost Escrow
Account" below.

RESERVE FOR FUTURE TRUST EXPENSES

    In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. In the
first quarter of 1998, the Trust determined that the Trust's cash reserve was
sufficient at that time to provide for

                                       8
<PAGE>
future administrative expenses in connection with the winding up of the Trust.
The Trust determined that a cash reserve equal to three times the average
expenses of the Trust during each of the past three years was sufficient at this
time to provide for future administrative expenses in connection with the
winding up of the Trust. The reserve amount for 2000 was $1,117,484. The excess
amount of $266,759 was distributed to Unit holders in the first quarter of 2000.
The reserve amount for 2001 is $978,971. The excess amount in the reserve of
$138,513 was distributed to Unitholders in the first quarter of 2001.

OTHER

    The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of oil and gas produced from the Royalty
Properties. It should be noted that substantial uncertainties exist with regard
to future oil and gas prices, which are subject to material fluctuations due to
changes in production levels and pricing and other actions taken by major
petroleum producing nations, as well as the regional supply and demand for oil
and gas, weather, industrial growth, conservation measures, competition and
other variables.

OPERATIONAL REVIEW

THREE MONTHS ENDED MARCH 31, 2001 AND 2000

    VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY THE
WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.

    Ship Shoal 182/183 crude oil revenues increased from $3,125,806 in the first
quarter of 2000 to $3,199,913 in the first quarter of 2001, primarily due to an
increase in the average crude oil price from $25.41 per barrel in the first
quarter of 2000 to $30.70 per barrel for the same period in 2001. The increase
in the average crude oil price was partially offset by a decrease in crude oil
production from 123,037 barrels in the first quarter of 2000 to 104,228 in the
first quarter of 2001. The decrease in crude oil production was due primarily to
the continued natural production decline of these properties. Gas revenues
increased from $766,292 in the first quarter of 2000 to $996,265 in the first
quarter of 2001 primarily due to an increase in the average natural gas sales
price from $2.52 per Mcf in the first quarter of 2000 to $7.46 per Mcf for the
same period in 2001. The significant increase in the average natural gas price
was partially offset by a decrease in natural gas production from 282,651 Mcf in
the first quarter of 2000 to 133,481 Mcf in the first quarter of 2001. The
decrease in gas volumes was primarily as a result of poor weather that delayed
workers and work on the platform, an intermittent flow on the C-10 well and
increased water in the B-15 well. The gas from Ship Shoal 182/183 is committed
to Dynegy Inc. ("Dynegy") at a calculated price based on the monthly Inside FERC
Tennessee-Louisiana Zone 1 Index. In addition, the Working Interest Owner has
advised the Trust that approximately 66,026 Mcf have been overtaken by the
Working Interest Owner from this property as of January 31, 2001, down from
100,963 Mcf as of January 31, 2000. The Trust's share of this overtake position
as of January 31, 2001 is approximately 16,506 Mcf. Accordingly, gas revenues
from this property may be decreased in future periods while underproduced
parties recoup their share of the gas imbalance. Chevron has advised the Trust
that sufficient gas reserves exist on Ship Shoal 182/183 for underproduced
parties to recoup their share of the gas imbalance on this property. Capital
expenditures decreased from $160,129 in the first quarter of 2000 to $71,950 in
the first quarter of 2001 primarily due to sumpwork on the C well and reservoir
stimulation on the C and E wells in the first quarter of 2000. Operating
expenses decreased from $454,064 in the first quarter of 2000 to $327,327 for
the same period in 2001.

                                       9
<PAGE>
    Eugene Island 339 crude oil revenues decreased from $1,685,752 in the first
quarter of 2000 to $1,512,491 for the same period in 2001 due to a decrease in
volumes from 69,118 in the first quarter of 2000 to 51,385 barrels in the first
quarter of 2001 due primarily to the continued natural production decline of the
properties. The decrease in volumes was partially offset by an increase in the
average crude oil price from $24.39 per barrel in the first quarter of 2000 to
$29.43 per barrel in the first quarter of 2001. Gas revenues decreased from
$217,218 in the first quarter of 2000 to $178,630 in the first quarter of 2001
primarily due to a decrease in natural gas volumes from 90,641 Mcf in the first
quarter of 2000 to 20,591 Mcf in the first quarter of 2001. The decrease in
natural gas volumes was partially offset by an increase in the average price of
natural gas from $2.40 per Mcf in the first quarter of 2000 to $8.68 per Mcf for
the same period in 2001. The Working Interest Owner has advised the Trust that
there is an overtake imbalance position of approximately 5,281 Mcf on this
property as of November 30, 2000. The Trust's share of this overtake position is
approximately 1,320 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced parties recoup their share of the
gas imbalance. Chevron has advised the Trust that sufficient gas reserves exist
on the Eugene Island 339 for underproduced parties to recoup their share of the
gas imbalance on this property. The gas from this property is currently
committed to Dynegy at a calculated price based on the monthly Inside FERC
Tennessee-Louisiana Zone 1 Index. Capital expenditures decreased from $519,352
in the first quarter of 2000 to $65,308 in the first quarter of 2001 due to
sidetrack drilling and facility improvements during the first quarter of 2000
and the absence of drilling in 2001. Operating expenses decreased from $391,922
in the first quarter of 2000 to $278,654 in the first quarter of 2001.

    West Cameron 643 gas revenues increased from $1,328,252 in the first quarter
of 2000 to $1,759,238 in the first quarter of 2001 primarily due to a
significant increase in the average price received for natural gas from $2.58
per Mcf in the first quarter of 2000 to $6.98 per Mcf in the first quarter of
2001. The increase in the average price received was partially offset by a
significant decrease in gas volumes from 513,897 Mcf in the first quarter of
2000 to 252,100 Mcf for the same period in 2000. The decrease in volumes was
primarily due to the A-4 and A-10 wells going off production. The gas from West
Cameron 643 is currently committed to Texaco Natural Gas Inc. ("TNGI"). TNGI is
a wholly owned affiliate of Texaco Exploration and Production Inc. ("TEPI").
TNGI purchases natural gas from TEPI and resells such gas to a variety of
third-party customers at a variety of downstream delivery points. The prices
that TNGI pays TEPI for the gas production is based on the actual sale prices
that TNGI receives from its third-party customers less the actual transportation
cost, if any, that TNGI pays to a transporting pipeline. TEPI's proceeds are
based on 100% of the actual resale price of the gas, less actual transportation.
The Working Interest Owner has advised the Trust that approximately 22,853 Mcf
have been overtaken by the Working Interest Owner from this property as of
November 30, 2000. The Trust's share of this overtake position is approximately
5,713 Mcf. Accordingly, gas revenues from this property may be reduced in future
periods while underproduced parties recover their share of the gas imbalance.
Operating expenses decreased from $426,197 in the first quarter of 2000 to
$335,565 for the same period in 2001 primarily due to maintenance work performed
during the first quarter of 2000. Capital expenditures decreased from $99,194 in
the first quarter of 2000 to $28,866 as compared to the same period in 2001, due
primaily to perforating and test work done on the A-10 sidetrack well in the
first quarter of 2000.

    East Cameron 371/381 crude oil revenues decreased from $276,154 in the first
quarter of 2000 to $53,041 in the first quarter of 2001 primarily due to a
decrease in crude oil production from 10,528 barrels in the first quarter of
2000 to 1,694 barrels for the same period in 2001. The volume decrease was
partially offset by an increase in the average crude oil price from $26.23 per
barrel in the first quarter of 2000 to

                                       10
<PAGE>
$31.31 per barrel in the first quarter of 2001. Gas revenues decreased from
$562,872 in the first quarter of 2000 to $416,213 in the first quarter of 2001
primarily due to a decrease in gas volumes from 225,905 Mcf in the first quarter
of 2000 to 53,571 Mcf for the same period in 2001. The decrease in gas volumes
was partially offset by an increase in the average price received for natural
gas from $2.56 per Mcf in the first quarter of 2000 to $7.77 per Mcf in the
first quarter of 2001. Capital expenditures decreased from $177,512 in the first
quarter of 2000 to $(1,281) in the first quarter of 2001 due to a transfer of
casing to warehouse stock in the first quarter of 2001. Operating expenses
decreased from $34,254 in the first quarter of 2000 to $18,274 in the first
quarter of 2001.

FUTURE NET REVENUES AND TERMINATION OF THE TRUST

    Based on a reserve study provided to the Trust by DeGolyer and MacNaughton,
independent petroleum engineers, it was estimated that as of October 31, 2000
future net revenues attributable to the Trust's royalty interests approximated
$28.7 million. Such reserve study also indicates that approximately 75% of the
future net revenues from the Royalty Properties are expected to be received by
the Trust during the next three years. In addition, because the Trust will
terminate in the event estimated future net revenues fall below $2 million, it
would be possible for the Trust to terminate even though some or all of the
Royalty Properties continued to have remaining productive lives. Upon
termination of the Trust, the Trustees will sell for cash all of the assets held
in the Trust estate and make a final distribution to Unit holders of any funds
remaining after all Trust liabilities have been satisfied. The estimates of
future net revenues discussed above are subject to large variances from year to
year and should not be construed as exact. There are numerous uncertainties
present in estimating future net revenues for the Royalty Properties. The
estimate may vary depending on changes in market prices for crude oil and
natural gas, the recoverable reserves, annual production and costs assumed by
DeGolyer and MacNaughton. In addition, future economic and operating conditions
as well as results of future drilling plans may cause significant changes in
such estimate. The discussion set forth above is qualified in its entirety by
reference to the Trust's 2000 Annual Report on Form 10-K. The Form 10-K is
available upon request from the Corporate Trustee.

SPECIAL COST ESCROW ACCOUNT

    The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royalty
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on factors including estimates of aggregate future production
costs, aggregate future Special Costs, aggregate future net revenues and actual
current net proceeds. Deposits into this account reduce current distributions
and are placed in an escrow account and invested in short-term certificates of
deposit. Such account is herein referred to as the "Special Cost Escrow
Account." The Trust's share of interest generated from the Special Cost Escrow
Account serves to reduce the Trust's share of allocated production costs.
Special Cost Escrow funds will generally be utilized to pay Special Costs to the
extent there are not adequate current net proceeds to pay such costs. Special
Costs that have been paid are no longer included in the Special Cost Escrow
calculation. Deposits to the Special Cost Escrow Account will generally be made
when the balance in the Special Cost Escrow Account is less than 125% of future
Special Costs and there is a Net Revenues Shortfall (a calculation of the excess
of estimated future costs over estimated future net revenues pursuant to a
formula contained in the Conveyance). When there is not a Net Revenues
Shortfall, amounts

                                       11
<PAGE>
in the Special Cost Escrow Account will generally be released, to the extent
that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account generally will also be released when the balance in such account exceeds
125% of future Special Costs. In the first quarter of 2000, there was a deposit
of funds into the Special Cost Escrow Account. The Trust's share of the funds
deposited was approximately $265,000. The deposit was primarily a result of an
increase in the Working Interest Owners' current estimate of projected capital
expenditures on the Royalty Properties. In the first quarter of 2001, there was
a net deposit of funds into the Special Cost Escrow Account. The Trust's share
of the funds deposited was approximately $423,125. The deposit was primarily a
result of an increase in the Working Interest Owners' current estimate of
projected capital exenditures of the Royalty Properties. As of March 31, 2001,
approximately $5,733,000 remained in the Special Cost Escrow Account.

    Chevron, in its capacity as Managing General Partner, has advised the Trust
that additional deposits to the Special Cost Escrow Account may be required in
future periods in connection with other production costs, other abandonment
costs, other capital expenditures and changes in the estimates and factors
described above. Such deposits, if made, could result in a significant reduction
in Royalty income in the periods in which such deposits are made, including the
possibility that no Royalty income would be received in such periods.

                                       12
<PAGE>
OVERVIEW OF PRODUCTION, PRICES AND NET PROCEEDS

    The following schedule provides a summary of the volumes and weighted
average prices for crude oil and condensate and natural gas recorded by the
Working Interest Owners for the Royalty Properties, as well as the Working
Interest Owners' calculations of the net proceeds and the royalties paid to the
Trust during the periods indicated. Net proceeds due to the Trust are calculated
for each three month period commencing on the first day of February, May, August
and November.

<TABLE>
<CAPTION>
                                                                 ROYALTY PROPERTIES
                                                                 THREE MONTHS ENDED
                                                                    MARCH 31,(1)
                                                              -------------------------
                                                                 2001          2000
                                                              -----------   -----------
<S>                                                           <C>           <C>
Crude oil and condensate (bbls).............................      164,657       208,346
Natural gas and gas products (Mcf)..........................      603,668     1,287,141
Crude oil and condensate average price, per bbl.............  $     30.35   $     25.22
Natural gas average price, per Mcf (excluding gas
  products).................................................  $      6.98   $      2.55
Crude oil and condensate revenues...........................  $ 4,997,290   $ 5,254,985
Natural gas and gas products revenues.......................    4,109,267     3,242,830
Production expenses.........................................     (978,491)   (1,374,245)
Capital expenditures........................................     (196,139)     (967,684)
Undistributed Net Loss (Income)(2)..........................     (164,248)      (90,746)
(Provision for) Refund of escrowed special costs............   (1,692,500)   (1,059,916)
                                                              -----------   -----------
NET PROCEEDS................................................  $ 6,075,179   $ 5,005,224
Royalty interest............................................         x25%          x25%
                                                              -----------   -----------
Partnership share...........................................  $ 1,518,795   $ 1,251,306
Trust interest..............................................      x99.99%       x99.99%
                                                              -----------   -----------
Trust share.................................................  $ 1,518,643   $ 1,251,181
                                                              ===========   ===========
</TABLE>

---------

(1) The amounts for the three months ended March 31, 2001 and 2000 represent
    actual production for the periods November 2000 through January 2001, and
    November 1999 through January 2000, respectively.

(2) Undistributed net loss represents negative Net Proceeds generated during the
    respective period. An undistributed net loss is carried forward and offset,
    in future periods, by positive Net Proceeds earned by the related Working
    Interest Owner(s). Undistributed net income represents positive Net
    Proceeds, generated during the respective period, that were applied to an
    existing loss carryforward. As of March 31, 2001, the loss carryforward was
    $715,764 ($178,941 net to the Trust).

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

    No material changes have occurred since our Annual Report on Form 10-K for
the year-ended December 31, 2000. Reference is also made to Note 2 of the Notes
to Financial Statements included in Item 1 of this Form 10-Q.

                                       13
<PAGE>
                          PART II -- OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) EXHIBITS

    (Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)

<TABLE>
<CAPTION>
                                                                                                    SEC FILE OR
                                                                                                    REGISTRATION   EXHIBIT
                                                                                                       NUMBER       NUMBER
                                                                                                    ------------   --------
    <S>                     <C>         <C>                                                         <C>            <C>
    4(a)*                   --          Trust Agreement dated as of January 1, 1983, among Tenneco
                                        Offshore Company, Inc., Texas Commerce Bank National
                                        Association, as corporate trustee, and Horace C. Bailey,
                                        Joseph C. Broadus and F. Arnold Daum, as individual
                                        trustees (Exhibit 4(a) to Form 10-K for the year ended
                                        December 31, 1992 of TEL Offshore Trust)..................     0-6910          4(a)
    4(b)*                   --          Agreement of General Partnership of TEL Offshore Trust
                                        Partnership between Tenneco Oil Company and the TEL
                                        Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to
                                        Form 10-K for year ended December 31, 1992 of TEL Offshore
                                        Trust)....................................................     0-6910          4(b)
    4(c)*                   --          Conveyance of Overriding Royalty Interests from
                                        Exploration I to the Partnership (Exhibit 4(c) to
                                        Form 10-K for year ended December 31, 1992 of TEL Offshore
                                        Trust)....................................................     0-6910          4(c)
    4(d)*                   --          Amendments to TEL Offshore Trust Trust Agreement, dated
                                        December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended
                                        December 31, 1992 of TEL Offshore Trust)..................     0-6910          4(d)
    4(e)*                   --          Amendment to the Agreement of General Partnership of TEL
                                        Offshore Trust Partnership, effective as of January 1,
                                        1983 (Exhibit 4(e) to Form 10-K for year ended
                                        December 31, 1992 of TEL Offshore Trust)..................     0-6910          4(e)
    10(a)*                  --          Purchase Agreement, dated as of December 7, 1984 by and
                                        betwee Tenneco Oil Company and Tenneco Offshore II Company
                                        (Exhibit 10(a) to Form 10-K for year ended December 31,
                                        1992, of TEL Offshore Trust)..............................     0-6910         10(a)
    10(b)*                  --          Consent Agreement, dated November 16, 1988, between TEL
                                        Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to
                                        Form 10-K for year ended December 31, 1988 of TEL Offshore
                                        Trust)....................................................     0-6910         10(b)
    10(c)*                  --          Assignment and Assumption Agreement, dated November 17,
                                        1988, between Tenneco Oil Company and TOC-Gulf of
                                        Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended
                                        December 31, 1988 of TEL Offshore Trust)..................     0-6910         10(c)
    10(d)*                  --          Gas Purchase and Sales Agreement Effective September 1,
                                        1993 between Tennessee Gas Pipeline Company and Chevron
                                        U.S.A. Production Company (Exhibit 10(d) to Form 10-K for
                                        year ended December 31, 1993 of TEL Offshore Trust).......     0-6910         10(d)
</TABLE>

(b) REPORTS ON FORM 8-K

    No reports on Form 8-K were filed with the Securities and Exchange
Commission during the first quarter of 2001.

                                       14
<PAGE>
                                   SIGNATURES

    Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

<TABLE>
<S>                                         <C>        <C>
                                            TEL OFFSHORE TRUST

                                            By:        The Chase Manhattan Bank, Corporate
                                                       Trustee

                                            By:                     /s/ MIKE ULRICH
                                                       -----------------------------------------
                                                                      MIKE ULRICH
                                                                 SENIOR VICE PRESIDENT
                                                                   AND TRUST OFFICER
</TABLE>

Date: May 9, 2001

The Registrant, TEL Offshore Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.

                                       15